This invention relates generally to wellbores, and in particular to cementing systems for wellbores.
Referring to FIG. 1a, a conventional system 10 for cementing a wellbore 12 includes a shoe 14 defining a passage 14a that is coupled to an end of a tubular member 16 defining a passage 16a. The tubular member 16 typically includes one or more tubular members threadably coupled end to end. The other end of the tubular member 16 is coupled to an end of a float collar 18 including a float 18a. The other end of the float collar 18 is coupled to an end of a tubular member 20 defining a passage 20a. Centralizers 22a, 22b, and 22c are coupled to the exteriors of the tubular members, 16 and 18. More generally, the system 10 may include any number of centralizers. The other end of the tubular member 20 is coupled to a fluid injection assembly 24 defining a passage 24a and radial passages 24b, 24c, and 24d, and including retaining pins 24e and 24f. The fluid injection head 24 is commonly referred to as a cementing head. A bottom cementing plug 26 and a top cementing plug 28 are retained within the passage 24a of the fluid injection assembly 24 by the retaining pins 24e and 24f. The bottom cementing plug 26 typically includes a longitudinal passage that is sealed off by a frangible diaphragm.
During operation, as illustrated in FIG. 1a, drilling mud 30 is circulated through the wellbore 12 by injecting the drilling mud into the fluid injection assembly 24 through the radial passage 24b. The drilling mud 30 then passes through the passages 24a, 20a, 18a, and 14a into the annulus between the tubular member 20, the float collar 18, the tubular member 16, and the shoe 14. As illustrated in FIG. 1b, the bottom cementing plug 26 is then released and a spacer fluid 32 followed by a cement slurry 34 are injected into the injection assembly 24 through the radial passage 24c behind and above the bottom cementing plug. As illustrated in FIG. 1c, the top cementing plug 28 is then released and a displacing fluid 36 is injected into the injection assembly 24 through the radial passage 24d behind and above the top cementing plug. As illustrated in FIG. 1d, the continued injection of the displacing fluid 36 displaces the bottom cementing plug 26 into contact with the float collar 18 and breaks the frangible membrane of the bottom cementing plug thereby causing the cement slurry 34 to flow into the annulus between the wellbore 12 and the shoe 14, the tubular member 16, the float collar 18, and the tubular member 20. As illustrated in FIG. 1e, the continued injection of the displacing fluid 36 then displaces the top cementing plug 28 downwardly until the top cementing plug impacts the bottom cementing plug 26. The float element 18a of the float collar 18 prevents back flow of the cement slurry 34 into the tubular member 20. The cement slurry 34 may then be allowed to cure.
Referring to FIG. 2a, another conventional system 100 for cementing a wellbore 102 having a preexisting wellbore casing 104 includes a float shoe 106 including a float element 106a that is coupled to an end of a tubular member 108 defining a passage 108a. The other end of the tubular member 108 is coupled to an end of a landing collar 110 defining a passage 110a. The other end of the landing collar 110 is coupled to an end of a tubular member 112 defining a passage 112a. A liner hanger 114 is coupled to the tubular member 112 for permitting the tubular member to be coupled to and supported by the preexisting wellbore casing 104. A centralizer 116 is also coupled to the exterior of the tubular member 112 for centrally positioning the tubular member inside the preexisting wellbore casing 104. An end of a tubular support member 118 defining a passage 118a extends into the other end of the tubular member 112. A releasable coupling 120 is coupled to the tubular support member 118 for releasably coupling the tubular support member to the tubular member 112. A wiper plug 122 defining a restricted passage 122a is coupled to an end of the tubular support member 118 within the other end of the tubular member 112. A bumper 124 and a cup seal 126 are coupled to the exterior of the end of the tubular support member 118 within the tubular member 112.
During operation, as illustrated in FIG. 2a, drilling mud 128 is circulated through the wellbore 102 by injecting the drilling mud through the passages 118a, 122a, 112a, 110a, 108a, and 106a into the annulus between the float shoe 106, the tubular member 108, the landing collar 110, and the tubular member 112. As illustrated in FIG. 2b, a spacer fluid 130 followed by a cement slurry 132 are then injected into the passages 118a, 122a, and 112a behind and above the drilling mud 128. As illustrated in FIG. 2c, a pump down plug 134 is then injected into the passage 118a followed by a displacing fluid 136. As illustrated in FIG. 2d, the continued injection of the displacing fluid 136, causes the pump down plug 134 to engage the restricted passage 122a of the wiper plug 122 thereby disengaging the wiper plug from the end of the tubular support member 118. As a result, the wiper plug 122 and the pump down plug 134 are driven downwardly within the tubular member 112 by the continued injection of the displacing fluid 136 which in turn displaces the spacer fluid 130 and the cement slurry 132 into the annulus between the wellbore 102 and the float shoe 106, the tubular member 108, the landing collar 110 and the tubular member. As illustrated in FIG. 2e, the continued injection of the displacing fluid 136 causes the wiper plug 122 and the pump down plug 134 to impact the landing collar 110 and engage the passage 110a. Furthermore, as illustrated in FIG. 2e, the continued injection of the displacing fluid 136 fills the annulus between the wellbore 102 and the tubular member 112 with the cement slurry 132. The float element 106a of the float shoe 106 prevents back flow of the cement slurry into the tubular member 108. As illustrated in FIG. 2f, the tubular support member 118 is then decoupled from the tubular member 112 and raised away from the end of the tubular member 112. The spacer liquid 130 and any excess cement slurry 132 may then be removed by circulating drilling mud 138 through the annulus between the tubular support member 118 and the preexisting wellbore casing 104. The cement slurry 132 may then be allowed to cure.
Referring to FIG. 3a, yet another conventional system 200 for cementing a wellbore 202 having a preexisting wellbore casing 204 includes a float shoe 206 including a float element 206a that is coupled to an end of a tubular member 208 defining a passage 208a. The other end of the tubular member 208 is coupled to an end of a landing collar 210 defining a passage 210a. The other end of the landing collar 210 is coupled to an end of a tubular member 212 defining a passage 212a. A centralizer 214 is coupled to the exterior of the tubular member 212 for centrally positioning the tubular member inside the preexisting wellbore casing 204. An end of a tubular support member 216 defining a passage 216a extends into the other end of the tubular member 212 and the other end of the tubular support member 216 is coupled to a conventional subsea cementing head. A releasable coupling 218 is coupled to the tubular support member 216 for releasably coupling the tubular support member to the tubular member 212. A wiper plug 220 defining a restricted passage 220a is coupled to an end of the tubular support member 216 within the other end of the tubular member 212. A bumper 222 and a cup seal 224 are coupled to the exterior of the end of the tubular support member 216 within the tubular member 212.
During operation, as illustrated in FIG. 3a, drilling mud 226 is circulated through the wellbore 202 by injecting the drilling mud through the passages 216a, 220a, 212a, 210a, 208a, and 206a into the annulus between the float shoe 206, the tubular member 208, the landing collar 210, and the tubular member 212. As illustrated in FIG. 3b, a spacer fluid 228 followed by a cement slurry 230 are then injected into the passages 216a, 220a, and 212a behind and above the drilling mud 226. As illustrated in FIG. 3c, a pump down plug 232 is then injected into the passage 216a followed by a displacing fluid 234. As illustrated in FIG. 3d, the continued injection of the displacing fluid 234, causes the pump down plug 232 to engage the restricted passage 220a of the wiper plug 220 thereby disengaging the wiper plug from the end of the tubular support member 216. As a result, the wiper plug 220 and the pump down plug 232 are driven downwardly within the tubular member 212 by the continued injection of the displacing fluid 234 which in turn displaces the spacer fluid 228 and the cement slurry 230 into the annulus between the wellbore 202 and the float shoe 206, the tubular member 208, the landing collar 210 and the tubular member. As illustrated in FIG. 3e, the continued injection of the displacing fluid 234 causes the wiper plug 220 and the pump down plug 232 to impact the landing collar 210 and engage the passage 210a. Furthermore, as illustrated in FIG. 3e, the continued injection of the displacing fluid 234 fills the annulus between the wellbore 202 and the tubular member 212 with the cement slurry 230. The float element 206a of the float shoe prevents back flow of the cement slurry 230 into the tubular member 208. The tubular support member 216 is then decoupled from the tubular member 212 and raised out of the wellbore 202. The cement slurry 230 may then be allowed to cure.
Thus, conventional systems for cementing a wellbore require the use of a float collar and/or a float shoe in order to prevent the back flow of the cement slurry. As a result, conventional systems for cementing a wellbore typically restrict circulation, and generate surge pressures that can damage the subterranean formations and induce the loss of valuable drilling fluids. Furthermore, conventional systems also increase casing and liner running times and open hole exposure times, and expose floating valves to drilling fluid circulation thereby eroding the floating valves and compromising their proper operation. Furthermore, the conventional equipment used for cementing wellbores is also complex, and is expensive to operate. In addition, because conventional float collars and/or float shoes, and the required related operating equipment, are large, heavy, and fragile, the cost of transporting such equipment is often expensive.
The present invention is directed to overcoming one or more of the limitations of existing cementing systems for wellbores.